Edgar Filing: OGE ENERGY CORP.

oge2ndqtr10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2010

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission File Number: 1-12579

OGE ENERGY CORP.

(Exact name of registrant as specified in its charter)

Oklahoma		73-1481638
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

321 North Harvey

P.O. Box 321

Oklahoma City, Oklahoma 73101-0321

(Address of principal executive offices)

(Zip Code)

405-553-3000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þ Yes o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ	Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No þ

At June 30, 2010, there were 97,372,989 shares of common stock, par value $0.01 per share, outstanding.

OGE ENERGY CORP.

FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2010

TABLE OF CONTENTS


		Page

FORWARD-LOOKING STATEMENTS		1


Part I – FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)
Condensed Consolidated Statements of Income		2
Condensed Consolidated Statements of Cash Flows		3
Condensed Consolidated Balance Sheets		4
Condensed Consolidated Statements of Changes in Stockholders’ Equity		6
Notes to Condensed Consolidated Financial Statements		8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		35

Item 3. Quantitative and Qualitative Disclosures About Market Risk		61

Item 4. Controls and Procedures		62


Part II – OTHER INFORMATION

Item 1. Legal Proceedings		62

Item 1A. Risk Factors		64

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		64

Item 6. Exhibits		65

Signature		66

FORWARD-LOOKING STATEMENTS

Except for the historical statements contained herein, the matters discussed in this Form 10-Q, including those matters discussed in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate”, “believe”, “estimate”, “expect”, “intend”, “objective”, “plan”, “possible”, “potential”, “project” and similar expressions. Actual results may vary materially from those expressed in forward-looking statements. In addition to the specific risk factors discussed in “Item 1A. Risk Factors” in OGE Energy Corp.’s Annual Report on Form 10-K for the year ended December 31, 2009 (“2009 Form 10-K”) and “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” herein, factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

Ÿ	general economic conditions, including the availability of credit, access to existing lines of credit, access to the commercial paper markets, actions of rating agencies and their impact on capital expenditures;

Ÿ	the ability of OGE Energy Corp. (collectively, with its subsidiaries, the “Company”) and its subsidiaries to access the capital markets and obtain financing on favorable terms;

Ÿ	prices and availability of electricity, coal, natural gas and natural gas liquids, each on a stand-alone basis and in relation to each other;

Ÿ	business conditions in the energy and natural gas midstream industries;

Ÿ	competitive factors including the extent and timing of the entry of additional competition in the markets served by the Company;

Ÿ	unusual weather;

Ÿ	availability and prices of raw materials for current and future construction projects;

Ÿ	Federal or state legislation and regulatory decisions and initiatives that affect cost and investment recovery, have an impact on rate structures or affect the speed and degree to which competition enters the Company’s markets;

Ÿ	environmental laws and regulations that may impact the Company’s operations;

Ÿ	changes in accounting standards, rules or guidelines;

Ÿ	the discontinuance of accounting principles for certain types of rate-regulated activities;

Ÿ	creditworthiness of suppliers, customers and other contractual parties;

Ÿ	the higher degree of risk associated with the Company’s nonregulated business compared with the Company’s regulated utility business; and

Ÿ	other risk factors listed in the reports filed by the Company with the Securities and Exchange Commission including those listed in “Item 1A. Risk Factors” and in Exhibit 99.01 to the Company’s 2009 Form 10-K.

The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.


OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions, except per share data)		2010		2009		2010		2009
OPERATING REVENUES
Electric Utility operating revenues	$	512.8	$	425.3	$	956.8	$	762.0
Natural Gas Pipeline operating revenues		374.4		218.8		806.2		488.7
Total operating revenues		887.2		644.1		1,763.0		1,250.7
COST OF GOODS SOLD (exclusive of depreciation and amortization
shown below)
Electric Utility cost of goods sold		218.9		176.4		457.8		335.5
Natural Gas Pipeline cost of goods sold		287.6		147.8		618.8		341.9
Total cost of goods sold		506.5		324.2		1,076.6		677.4
Gross margin on revenues		380.7		319.9		686.4		573.3
Other operation and maintenance		135.0		105.6		258.6		222.1
Depreciation and amortization		71.2		64.6		141.5		127.2
Impairment of assets		---		1.4		---		1.4
Taxes other than income		23.0		21.9		48.0		44.2
OPERATING INCOME		151.5		126.4		238.3		178.4
OTHER INCOME (EXPENSE)
Loss in earnings of unconsolidated affiliate		(1.3)		---		(1.3)		---
Interest income		---		0.4		---		1.1
Allowance for equity funds used during construction		2.3		3.9		4.6		5.2
Other income		3.4		6.5		6.5		13.0
Other expense		(3.7)		(2.7)		(6.1)		(5.0)
Net other income		0.7		8.1		3.7		14.3
INTEREST EXPENSE
Interest on long-term debt		33.4		31.9		67.0		63.3
Allowance for borrowed funds used during construction		(1.0)		(1.9)		(2.2)		(3.0)
Interest on short-term debt and other interest charges		1.6		1.7		3.3		4.1
Interest expense		34.0		31.7		68.1		64.4
INCOME BEFORE TAXES		118.2		102.8		173.9		128.3
INCOME TAX EXPENSE		40.3		31.9		70.8		39.8
NET INCOME		77.9		70.9		103.1		88.5
Less: Net income attributable to noncontrolling interest		0.6		0.4		1.6		1.2
NET INCOME ATTRIBUTABLE TO OGE ENERGY	$	77.3	$	70.5	$	101.5	$	87.3
BASIC AVERAGE COMMON SHARES OUTSTANDING		97.3		96.5		97.2		95.6
DILUTED AVERAGE COMMON SHARES OUTSTANDING		98.7		97.5		98.6		96.4
BASIC EARNINGS PER AVERAGE COMMON SHARE
ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS	$	0.79	$	0.73	$	1.04	$	0.91
DILUTED EARNINGS PER AVERAGE COMMON SHARE
ATTRIBUTABLE TO OGE ENERGY COMMON SHAREHOLDERS	$	0.78	$	0.72	$	1.03	$	0.91
DIVIDENDS DECLARED PER SHARE	$	0.3625	$	0.3550	$	0.7250	$	0.7100

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Six Months Ended
	June 30,
(In millions)	2010		2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	103.1	$	88.5
Adjustments to reconcile net income to net cash provided from
operating activities
Loss in earnings of unconsolidated affiliate		1.3		---
Depreciation and amortization		141.5		127.2
Impairment of assets		---		1.4
Deferred income taxes and investment tax credits, net		52.2		52.9
Allowance for equity funds used during construction		(4.6)		(5.2)
Loss on disposition and abandonment of assets		0.9		0.3
Stock-based compensation expense		3.9		2.8
Stock-based compensation converted to cash for tax withholding		(1.6)		(1.7)
Price risk management assets		(4.4)		6.1
Price risk management liabilities		11.4		(63.0)
Other assets		11.7		4.9
Other liabilities		(40.7)		(39.2)
Change in certain current assets and liabilities
Accounts receivable, net		(24.1)		33.1
Accrued unbilled revenues		(24.4)		(26.6)
Income taxes receivable		150.6		(27.3)
Fuel, materials and supplies inventories		(28.5)		(34.4)
Gas imbalance assets		(1.8)		3.9
Fuel clause under recoveries		(0.6)		23.9
Other current assets		8.9		(0.5)
Accounts payable		4.8		(74.3)
Customer deposits		18.3		2.6
Accrued taxes		20.4		16.4
Accrued interest		(7.8)		10.6
Accrued compensation		(3.6)		(3.5)
Gas imbalance liabilities		(4.2)		(13.2)
Fuel clause over recoveries		(50.1)		118.8
Other current liabilities		8.9		(17.6)
Net Cash Provided from Operating Activities		341.5		186.9
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (less allowance for equity funds used during
construction)		(296.6)		(491.2)
Construction reimbursement		3.3		17.6
Proceeds from sale of assets		1.6		0.7
Other investing activities		0.1		---
Net Cash Used in Investing Activities		(291.6)		(472.9)
CASH FLOWS FROM FINANCING ACTIVITIES
Retirement of long-term debt		(289.2)		---
Dividends paid on common stock		(70.4)		(67.5)
(Decrease) increase in short-term debt		(62.1)		84.2
Repayment of line of credit		(50.0)		(40.0)
Issuance of common stock		9.8		68.7
Proceeds from line of credit		115.0		80.0
Proceeds from long-term debt		246.2		198.4
Net Cash (Used in) Provided from Financing Activities		(100.7)		323.8
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(50.8)		37.8
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		58.1		174.4
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	7.3	$	212.2

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS


	June 30,		December 31,
	2010		2009
(In millions)	(Unaudited)

ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	7.3	$	58.1
Accounts receivable, less reserve of $1.7 and $2.4, respectively		315.5		291.4
Accrued unbilled revenues		81.6		57.2
Income taxes receivable		7.1		157.7
Fuel inventories		140.5		118.5
Materials and supplies, at average cost		84.9		78.4
Price risk management		8.0		1.8
Gas imbalances		5.0		3.2
Accumulated deferred tax assets		37.0		39.8
Fuel clause under recoveries		0.9		0.3
Prepayments		6.4		8.7
Other		3.4		11.0
Total current assets		697.6		826.1

OTHER PROPERTY AND INVESTMENTS, at cost		41.6		43.7

PROPERTY, PLANT AND EQUIPMENT
In service		8,925.8		8,617.8
Construction work in progress		250.5		335.4
Total property, plant and equipment		9,176.3		8,953.2
Less accumulated depreciation		3,119.4		3,041.6
Net property, plant and equipment		6,056.9		5,911.6

DEFERRED CHARGES AND OTHER ASSETS
Income taxes recoverable from customers, net		39.8		19.1
Benefit obligations regulatory asset		341.3		357.8
Price risk management		2.5		4.3
Unamortized loss on reacquired debt		16.0		16.5
Unamortized debt issuance costs		16.7		15.3
Other		81.7		72.3
Total deferred charges and other assets		498.0		485.3

TOTAL ASSETS	$	7,294.1	$	7,266.7

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

OGE ENERGY CORP.
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)


	June 30,		December 31,
	2010		2009
(In millions)	(Unaudited)

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Short-term debt	$	112.9	$	175.0
Accounts payable		277.2		297.0
Dividends payable		35.3		35.1
Customer deposits		93.5		85.6
Accrued taxes		55.8		37.0
Accrued interest		52.8		60.6
Accrued compensation		46.5		50.1
Long-term debt due within one year		---		289.2
Price risk management		9.6		14.2
Gas imbalances		7.8		12.0
Fuel clause over recoveries		137.4		187.5
Other		41.3		32.4
Total current liabilities		870.1		1,275.7

LONG-TERM DEBT		2,402.6		2,088.9

DEFERRED CREDITS AND OTHER LIABILITIES
Accrued benefit obligations		337.5		369.3
Accumulated deferred income taxes		1,321.1		1,246.6
Accumulated deferred investment tax credits		11.3		13.1
Accrued removal obligations, net		175.5		168.2
Price risk management		---		0.1
Other		56.3		44.0
Total deferred credits and other liabilities		1,901.7		1,841.3

Total liabilities		5,174.4		5,205.9

COMMITMENTS AND CONTINGENCIES (NOTE 12)

STOCKHOLDERS’ EQUITY
Common stockholders’ equity		902.3		887.7
Retained earnings		1,258.7		1,227.8
Accumulated other comprehensive loss, net of tax		(62.9)		(74.7)
Total OGE Energy stockholders’ equity		2,098.1		2,040.8
Noncontrolling interest		21.6		20.0
Total stockholders’ equity		2,119.7		2,060.8

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	7,294.1	$	7,266.7

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
(Unaudited)

		Premium		Accumulated
		on		Other
	Common	Capital	Retained	Comprehensive	Noncontrolling
(In millions)	Stock	Stock	Earnings	Income (Loss)	Interest	Total

Balance at December 31, 2009	$ 1.0	$ 886.7	$ 1,227.8	$ (74.7)	$ 20.0	$ 2,060.8
Comprehensive income (loss)
Net income for first quarter of 2010	---	---	24.2	---	1.0	25.2
Other comprehensive income (loss), net of tax
Defined benefit pension plan and restoration of
retirement income plan:
Amortization of deferred net loss, net of tax ($1.2 pre-tax)	---	---	---	0.5	---	0.5
Defined benefit postretirement plans:
Amortization of deferred net loss, net of tax ($1.0 pre-tax)	---	---	---	0.6	---	0.6
Amortization of deferred net transition obligation, net of tax ($0.2 pre-tax)	---	---	---	0.2	---	0.2
Amortization of prior service cost, net of tax (($0.2) pre-tax)	---	---	---	(0.2)	---	(0.2)
Deferred commodity contracts hedging losses, net of tax
(($4.3) pre-tax)	---	---	---	(2.7)	---	(2.7)
Amortization of cash flow hedge, net of tax ($0.1 pre-tax)	---	---	---	0.1	---	0.1
Other comprehensive loss	---	---	---	(1.5)	---	(1.5)
Comprehensive income (loss)	---	---	24.2	(1.5)	1.0	23.7
Dividends declared on common stock	---	---	(35.3)	---	---	(35.3)
Issuance of common stock	---	6.5	---	---	---	6.5
Balance at March 31, 2010	$ 1.0	$ 893.2	$ 1,216.7	$ (76.2)	$ 21.0	$ 2,055.7

Comprehensive income
Net income for second quarter of 2010	---	---	77.3	---	0.6	77.9
Other comprehensive income, net of tax
Defined benefit pension plan and restoration of
retirement income plan:
Amortization of deferred net loss, net of tax ($0.8 pre-tax)	---	---	---	0.5	---	0.5
Amortization of prior service cost, net of tax ($0.1 pre-tax)	---	---	---	0.1	---	0.1
Defined benefit postretirement plans:
Amortization of deferred net loss, net of tax ($0.5 pre-tax)	---	---	---	0.3	---	0.3
Amortization of deferred net transition obligation, net of tax ($0.2 pre-tax)	---	---	---	0.1	---	0.1
Deferred commodity contracts hedging gains, net of tax
($20.1 pre-tax)	---	---	---	12.3	---	12.3
Other comprehensive income	---	---	---	13.3	---	13.3
Comprehensive income	---	---	77.3	13.3	0.6	91.2
Dividends declared on common stock	---	---	(35.3)	---	---	(35.3)
Issuance of common stock	---	8.1	---	---	---	8.1
Balance at June 30, 2010	$ 1.0	$ 901.3	$ 1,258.7	$ (62.9)	$ 21.6	$ 2,119.7

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

OGE ENERGY CORP.
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY (CONTINUED)
(Unaudited)

		Premium		Accumulated
		on		Other
	Common	Capital	Retained	Comprehensive	Noncontrolling
(In millions)	Stock	Stock	Earnings	Income (Loss)	Interest	Total

Balance at December 31, 2008	$ 0.9	$ 802.0	$ 1,107.6	$ (13.7)	$ 17.2	$ 1,914.0
Comprehensive income (loss)
Net income for first quarter of 2009	---	---	16.8	---	0.8	17.6
Other comprehensive income (loss), net of tax
Defined benefit pension plan and restoration of
retirement income plan:
Amortization of deferred net loss, net of tax ($1.3 pre-tax)	---	---	---	0.8	---	0.8
Defined benefit postretirement plans:
Amortization of deferred net loss, net of tax ($0.2 pre-tax)	---	---	---	0.1	---	0.1
Deferred commodity contracts hedging losses, net of tax
(($46.2) pre-tax)	---	---	---	(28.3)	---	(28.3)
Amortization of cash flow hedge, net of tax ($0.2 pre-tax)	---	---	---	0.1	---	0.1
Other comprehensive loss	---	---	---	(27.3)	---	(27.3)
Comprehensive income (loss)	---	---	16.8	(27.3)	0.8	(9.7)
Dividends declared on common stock	---	---	(34.2)	---	---	(34.2)
Issuance of common stock	0.1	55.7	---	---	---	55.8
Balance at March 31, 2009	$ 1.0	$ 857.7	$ 1,090.2	$ (41.0)	$ 18.0	$ 1,925.9

Comprehensive income (loss)
Net income for second quarter of 2009	---	---	70.5	---	0.4	70.9
Other comprehensive income (loss), net of tax
Defined benefit pension plan and restoration of
retirement income plan:
Amortization of deferred net loss, net of tax ($1.3
pre-tax)	---	---	---	0.7	---	0.7
Amortization of prior service cost, net of tax
($0.1 pre-tax)	---	---	---	0.1	---	0.1
Defined benefit postretirement plans:
Amortization of prior service cost, net of tax
($0.1 pre-tax)	---	---	---	0.1	---	0.1
Deferred commodity contracts hedging losses, net of tax
(($32.4) pre-tax)	---	---	---	(19.8)	---	(19.8)
Amortization of cash flow hedge, net of tax ($0.1 pre-tax)	---	---	---	0.1	---	0.1
Other comprehensive loss	---	---	---	(18.8)	---	(18.8)
Comprehensive income (loss)	---	---	70.5	(18.8)	0.4	52.1
Dividends declared on common stock	---	---	(34.4)	---	---	(34.4)
Issuance of common stock	---	14.1	---	---	---	14.1
Balance at June 30, 2009	$ 1.0	$ 871.8	$ 1,126.3	$ (59.8)	$ 18.4	$ 1,957.7

The accompanying Notes to Condensed Consolidated Financial Statements are an integral part hereof.

OGE ENERGY CORP.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies

Organization

OGE Energy Corp. (“OGE Energy” and collectively, with its subsidiaries, the “Company”) is an energy and energy services provider offering physical delivery and related services for both electricity and natural gas primarily in the south central United States. The Company conducts these activities through four business segments: (i) electric utility, (ii) natural gas transportation and storage, (iii) natural gas gathering and processing and (iv) natural gas marketing. All significant intercompany transactions have been eliminated in consolidation.

The electric utility segment generates, transmits, distributes and sells electric energy in Oklahoma and western Arkansas. Its operations are conducted through Oklahoma Gas and Electric Company (“OG&E”) and are subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). OG&E was incorporated in 1902 under the laws of the Oklahoma Territory. OG&E is the largest electric utility in Oklahoma and its franchised service territory includes the Fort Smith, Arkansas area. OG&E sold its retail natural gas business in 1928 and is no longer engaged in the natural gas distribution business.

Enogex LLC and its subsidiaries (“Enogex”) are providers of integrated natural gas midstream services. Enogex is engaged in the business of gathering, processing, transporting and storing natural gas. Most of Enogex’s natural gas gathering, processing, transportation and storage assets are strategically located in the Arkoma and Anadarko basins of Oklahoma and the Texas Panhandle. Enogex’s operations are organized into two business segments: (i) natural gas transportation and storage and (ii) natural gas gathering and processing. Also, Enogex holds a 50 percent ownership interest in the Atoka Midstream, LLC joint venture (“Atoka”) through Enogex Atoka LLC, a wholly-owned subsidiary of Enogex Gathering & Processing LLC. The Company has consolidated 100 percent of Atoka in its consolidated financial statements as Enogex acts as the managing member of Atoka and has control over the operations of Atoka. Enogex is a Delaware single-member limited liability company.

The Company charges operating costs to its subsidiaries based on several factors. Operating costs directly related to specific subsidiaries are assigned to those subsidiaries. Where more than one subsidiary benefits from certain expenditures, the costs are shared between those subsidiaries receiving the benefits. Operating costs incurred for the benefit of all subsidiaries are allocated among the subsidiaries, either as overhead based primarily on labor costs or using the “Distrigas” method. The Distrigas method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment. The Company adopted the Distrigas method in January 1996 as a result of a recommendation by the OCC Staff. The Company believes this method provides a reasonable basis for allocating common expenses.

Basis of Presentation

The Condensed Consolidated Financial Statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles (“GAAP”) have been condensed or omitted pursuant to such rules and regulations; however, the Company believes that the disclosures are adequate to prevent the information presented from being misleading.

In the opinion of management, all adjustments necessary to fairly present the consolidated financial position of the Company at June 30, 2010 and December 31, 2009, the results of its operations for the three and six months ended June 30, 2010 and 2009 and the results of its cash flows for the six months ended June 30, 2010 and 2009, have been included and are of a normal recurring nature except as otherwise disclosed.

Due to seasonal fluctuations and other factors, the operating results for the three and six months ended June 30, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010 or for any future period. The Condensed Consolidated Financial Statements and Notes thereto should be read in conjunction with the audited Consolidated Financial Statements and Notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009 (“2009 Form 10-K”).

Accounting Records

The accounting records of OG&E are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and adopted by the OCC and the APSC. Additionally, OG&E, as a regulated utility, is subject to accounting principles for certain types of rate-regulated activities, which provide that certain actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s expected recovery of deferred costs and flowback of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.

OG&E records certain actual or anticipated costs and obligations as regulatory assets or liabilities if it is probable, based on regulatory orders or other available evidence, that the cost or obligation will be included in amounts allowable for recovery or refund in future rates.

The following table is a summary of OG&E’s regulatory assets and liabilities at:

	June 30,		December 31,
(In millions)	2010		2009
Regulatory Assets
Benefit obligations regulatory asset	$	341.3	$	357.8
Income taxes recoverable from customers, net		39.8		19.1
Deferred storm expenses		32.3		28.0
Unamortized loss on reacquired debt		16.0		16.5
Deferred pension plan expenses		15.8		18.1
Smart Grid		7.7		---
Red Rock deferred expenses		7.5		7.7
Fuel clause under recoveries		0.9		0.3
Miscellaneous		3.0		3.9
Total Regulatory Assets	$	464.3	$	451.4

Regulatory Liabilities
Accrued removal obligations, net	$	175.5	$	168.2
Fuel clause over recoveries		137.4		187.5
Miscellaneous		10.2		7.3
Total Regulatory Liabilities	$	323.1	$	363.0

For a discussion of regulatory assets related to OG&E’s Smart Grid program, see Note 13.

Management continuously monitors the future recoverability of regulatory assets. When in management’s judgment future recovery becomes impaired, the amount of the regulatory asset is adjusted, as appropriate. If the Company were required to discontinue the application of accounting principles for certain types of rate-regulated activities for some or all of its operations, it could result in writing off the related regulatory assets; the financial effects of which could be significant.

Reclassifications

Certain prior year amounts have been reclassified on the Condensed Consolidated Statement of Cash Flows to conform to the 2010 presentation related to a customer’s reimbursement of Enogex’s costs related to the ongoing construction of a transportation pipeline in 2009 and 2010.

2. Fair Value Measurements

The classification of the Company’s fair value measurements requires judgment regarding the degree to which market data are observable or corroborated by observable market data. GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value based on observable and unobservable data. The hierarchy categorizes the inputs into three levels, with the highest priority given to quoted prices in active markets for identical unrestricted assets or liabilities (Level 1) and the lowest priority given to unobservable inputs (Level 3). Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The three levels defined in the fair value hierarchy and examples of each are as follows:

Level 1 inputs are quoted prices in active markets for identical unrestricted assets or liabilities that are accessible at the measurement date. An example of instruments that may be classified as Level 1 are futures transactions for energy commodities traded on the New York Mercantile Exchange (“NYMEX”).

Level 2 inputs are inputs other than quoted prices in active markets included within Level 1 that are either directly or indirectly observable at the reporting date for the asset or liability for substantially the full term of the asset or liability. Level 2 inputs include quoted prices for similar assets or liabilities in active markets and quoted prices for identical or similar assets or liabilities in markets that are not active. An example of instruments that may be classified as Level 2 includes energy commodity purchase or sales transactions in a market such that the pricing is closely related to the NYMEX pricing.

Level 3 inputs are prices or valuation techniques for the asset or liability that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity). Unobservable inputs reflect the reporting entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk). An example of instruments that may be classified as Level 3 includes energy commodity purchase or sales transactions of a longer duration or in an inactive market such that there are no closely related markets in which quoted prices are available.

The Company utilizes the market approach in determining the fair value of its derivative positions by using either NYMEX published market prices, independent broker pricing data or broker/dealer valuations. The valuations of derivatives with pricing based on NYMEX published market prices may be considered Level 1 if they are settled through a NYMEX clearing broker account with daily margining. Over-the-counter derivatives with NYMEX based prices are considered Level 2 due to the impact of counterparty credit risk. Valuations based on independent broker pricing or broker/dealer valuations may be classified as Level 2 only to the extent they may be validated by an additional source of independent market data for an identical or closely related, active market. Otherwise, they are considered Level 3.

The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor’s Ratings Services (“Standard & Poor’s”) and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material.

Contracts with Master Netting Arrangements

Fair value amounts recognized for forward, interest rate swap, option and other conditional or exchange contracts executed with the same counterparty under a master netting arrangement may be offset. The reporting entity’s choice to offset or not must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, option and other conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Condensed Consolidated Balance Sheets. The Company has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation.

The following tables summarize the Company’s assets and liabilities that are measured at fair value on a recurring basis at June 30, 2010 and December 31, 2009 as well as reconcile the Company’s commodity contracts fair value to Price Risk Management (“PRM”) Assets and Liabilities on the Company’s Condensed Consolidated Balance Sheet at June 30, 2010 and December 31, 2009.

June 30, 2010
(In millions)	Quoted Market Prices in Active Market for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Master Netting Agreement Adjustments		Amounts Held in Clearing Broker Accounts Reflected in Other Current Assets			Balance Sheet Presentation
Assets
Commodity contracts	$	14.3	$	6.4	$	42.1	$	62.8	$	(36.6)		$	(15.7)	$	10.5
Gas imbalance assets (A)		---		5.0		---		5.0		---			---		5.0
Total	$	14.3	$	11.4	$	42.1	$	67.8	$	(36.6)		$	(15.7)	$	15.5

Liabilities
Commodity contracts	$	13.7	$	45.8	$	1.8	$	61.3	$	(36.6)		$	(15.1)	$	9.6
Gas imbalance liabilities (A)(B)		---		3.0		---		3.0		---			---		3.0
Total	$	13.7	$	48.8	$	1.8	$	64.3	$	(36.6)		$	(15.1)	$	12.6

(A) The Company uses the market approach to fair value its gas imbalance assets and liabilities, using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices.

(B) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of approximately $4.8 million, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

December 31, 2009
(In millions)	Quoted Market Prices in Active Market for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value		Master Netting Agreement Adjustments		Amounts Held in Clearing Broker Accounts Reflected in Other Current Assets			Balance Sheet Presentation
Assets
Commodity contracts	$	16.1	$	6.2	$	49.0	$	71.3	$	(47.9)		$	(17.3)	$	6.1
Gas imbalance assets (C)		---		3.2		---		3.2		---			---		3.2
Total	$	16.1	$	9.4	$	49.0	$	74.5	$	(47.9)		$	(17.3)	$	9.3

Liabilities
Commodity contracts	$	13.3	$	49.8	$	14.7	$	77.8	$	(47.9)		$	(15.6)	$	14.3
Gas imbalance liabilities (C)(D)		---		8.0		---		8.0		---			---		8.0
Total	$	13.3	$	57.8	$	14.7	$	85.8	$	(47.9)		$	(15.6)	$	22.3

(C) The Company uses the market approach to fair value its gas imbalance assets and liabilities, using an average of the Inside FERC Gas Market Report for Panhandle Eastern Pipe Line Co. (Texas, Oklahoma Mainline), ONEOK (Oklahoma) and ANR Pipeline (Oklahoma) indices.

(D) Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of approximately $4.0 million, which fuel reserves are based on the value of natural gas at the time the imbalance was created and which are not subject to revaluation at fair market value.

The following table summarizes the Company’s assets and liabilities that are measured at fair value on a recurring basis using significant unobservable inputs (Level 3).

Assets	Commodity Contracts
(In millions)	2010		2009
Balance at January 1	$	49.0	$	121.2
Total gains or losses
Included in other comprehensive income		(3.9)		(11.1)
Purchases, issuances, sales and settlements
Settlements		(4.1)		(4.5)
Balance at March 31	$	41.0	$	105.6
Total gains or losses
Included in other comprehensive income		7.2		(34.4)
Purchases, issuances, sales and settlements
Settlements		(6.1)		(3.9)
Balance at June 30	$	42.1	$	67.3
The amount of total gains or losses for the period included in earnings attributable
to the change in unrealized gains or losses relating to assets held at June 30	$	---	$	---

Liabilities	Commodity Contracts
(In millions)	2010		2009
Balance at January 1	$	14.7	$	---
Total gains or losses
Included in other comprehensive income		(5.1)		---
Purchases, issuances, sales and settlements
Settlements		(1.4)		---
Balance at March 31	$	8.2	$	---
Total gains or losses
Included in other comprehensive income		(3.7)		---
Purchases, issuances, sales and settlements
Purchases		---		1.8
Settlements		(2.7)		---
Balance at June 30	$	1.8	$	1.8
The amount of total gains or losses for the period included in earnings attributable
to the change in unrealized gains or losses relating to liabilities held at June 30	$	---	$	---

Gains and losses (realized and unrealized) included in earnings for the three and six months ended June 30, 2010 and 2009 attributable to the change in unrealized gains or losses relating to assets and liabilities held at June 30, 2010 and 2009, if any, are reported in Operating Revenues.

The following table summarizes the fair value and carrying amount of the Company’s financial instruments, including derivative contracts related to the Company’s PRM activities at June 30, 2010 and December 31, 2009.

	June 30, 2010						December 31, 2009
	Carrying			Fair			Carrying		Fair
(In millions)	Amount			Value			Amount		Value

Price Risk Management Assets
Energy Derivative Contracts	$	10.5	$		10.5	$	6.1	$		6.1

Price Risk Management Liabilities
Energy Derivative Contracts	$	9.6	$		9.6	$	14.3	$		14.3

Long-Term Debt
OG&E Senior Notes	$	1,654.9	$		1,872.6	$	1,406.4	$		1,492.1
OGE Energy Senior Notes		99.6			107.4		99.5			102.6
OG&E Industrial Authority Bonds		135.4			135.4		135.4			135.4
Enogex Senior Notes		447.7			484.9		736.8			746.7
Enogex Revolving Credit Agreement		65.0			65.0		---			---

The carrying value of the financial instruments on the Condensed Consolidated Balance Sheets not otherwise discussed above approximates fair value except for long-term debt which is valued at the carrying amount. The valuation of the Company’s energy derivative contracts was determined generally based on quoted market prices. However, in certain instances where market quotes are not available, other valuation techniques or models are used to estimate market values. The valuation of instruments also considers the credit risk of the counterparties. The fair value of the Company’s long-term debt is based on quoted market prices and management’s estimate of current rates available for similar issues with similar maturities.

3. Derivative Instruments and Hedging Activities

The Company is exposed to certain risks relating to its ongoing business operations. The primary risks managed using derivatives instruments are commodity price risk and interest rate risk. The Company is also exposed to credit risk in its business operations.

Commodity Price Risk

The Company primarily uses forward physical contracts, commodity price swap contracts and commodity price option features to manage the Company’s commodity price risk exposures. Commodity derivative instruments used by the Company are as follows:

Ÿ	natural gas liquids (“NGL”) put options and NGLs swaps are used to manage Enogex’s NGLs exposure associated with its processing agreements;

Ÿ	natural gas swaps are used to manage Enogex’s keep-whole natural gas exposure associated with its processing operations and Enogex’s natural gas exposure associated with operating its gathering, transportation and storage assets;

Ÿ	natural gas futures and swaps and natural gas commodity purchases and sales are used to manage OGE Energy’s natural gas marketing subsidiary, OGE Energy Resources, Inc.’s (“OERI”), natural gas exposure associated with its storage and transportation contracts; and

Ÿ	natural gas futures and swaps, natural gas options and natural gas commodity purchases and sales are used to manage OERI’s marketing and trading activities.

Management may designate certain derivative instruments for the purchase or sale of physical commodities, purchase or sale of electric power and fuel procurement discussed above as normal purchases and normal sales contracts. Normal purchases and normal sales contracts are not recorded in PRM Assets or Liabilities in the Condensed Consolidated Balance Sheets and earnings recognition is recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by its operations, (ii) commodity contracts for the sale of NGLs produced by Enogex’s gathering and processing business, (iii) electric power contracts by OG&E and (iv) fuel procurement by OG&E.

The Company recognizes its non-exchange traded derivative instruments as PRM Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and, therefore, are recorded at fair value on a net basis in Other Current Assets in the Condensed Consolidated Balance Sheets.

Interest Rate Risk

The Company’s exposure to changes in interest rates primarily relates to short-term variable debt and commercial paper. The Company manages its interest rate exposure by limiting its variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. The Company utilizes interest rate derivatives to alter interest rate exposure in an attempt to reduce interest expense related to existing debt issues. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

Credit Risk

The Company is exposed to certain credit risks relating to its ongoing business operations. Credit risk includes the risk that counterparties that owe the Company money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, the Company may be forced to enter into alternative arrangements. In that event, the Company’s financial results could be adversely affected and the Company could incur losses.

Cash Flow Hedges

For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income and recognized into earnings in the same period during which the hedged transaction affects earnings. The ineffective portion of a derivative’s change in fair value or hedge components excluded from the assessment of effectiveness is recognized currently in earnings. The Company measures the ineffectiveness of commodity cash flow hedges using the change in fair value method whereby the change in the expected future cash flows designated as the hedge transaction are compared to the change in fair value of the hedging instrument. Forecasted transactions, which are designated as the hedged transaction in a cash flow hedge, are regularly evaluated to assess whether they continue to be probable of occurring. If the forecasted transactions are no longer probable of occurring, hedge accounting will cease on a prospective basis and all future changes in the fair value of the derivative will be recognized directly in earnings.

The Company designates as cash flow hedges derivatives used to manage commodity price risk exposure for Enogex’s contractual long/short positions and operational storage natural gas, keep-whole natural gas and NGLs. Enogex’s cash flow hedging activity at June 30, 2010 covers the period from July 1, 2010 through December 31, 2011. The Company also designates as cash flow hedges certain derivatives used to manage commodity exposure for certain transportation and natural gas inventory positions at OERI. OERI does not have any derivative instruments designated as cash flow hedges at June 30, 2010.

Fair Value Hedges

For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedge risk are recognized currently in earnings. The Company includes the gain or loss on the hedged items in Operating Revenues as the offsetting loss or gain on the related hedging derivative.

At June 30, 2010 and December 31, 2009, the Company had no outstanding commodity derivative instruments that were designated as fair value hedges.

Derivatives Not Designated As Hedging Instruments

Derivative instruments not designated as hedging instruments are utilized in OERI’s asset management, marketing and trading activities and also include contracts formerly designated as cash flow hedges of Enogex’s NGLs, keep-whole natural gas and operational storage natural gas exposures. A portion of Enogex’s processing agreements, which were previously under keep-whole arrangements, were converted to fee-based arrangements. As a result, effective June 30, 2009 Enogex de-designated a portion of these derivatives and entered into offsetting derivatives to close the positions. For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.

Quantitative Disclosures Related to Derivative Instruments

At June 30, 2010, the Company had the following outstanding commodity derivative instruments that were designated as cash flow hedges.

		Gross Notional
	Commodity	Volume (A)		Maturity
	(In millions)
Short Financial Swaps/Futures (fixed)	NGLs		0.3	Current

Purchased Financial Options	NGLs		1.3	Current
Purchased Financial Options	NGLs		0.7	Non-Current
Total Purchased Financial Options			2.0

Long Financial Swaps/Futures (fixed)	Natural Gas		5.7	Current
Long Financial Swaps/Futures (fixed)	Natural Gas		2.6	Non-Current
Total Long Financial Swaps/Futures (fixed)			8.3

Short Financial Swaps/Futures (fixed)	Natural Gas		0.9	Current

Short Financial Basis Swaps	Natural Gas		0.9	Current

(A) Natural gas in million British thermal unit (“MMBtu”); NGLs in barrels.

At June 30, 2010, the Company had the following outstanding commodity derivative instruments that were not designated as either a cash flow or fair value hedge.

		Gross Notional
	Commodity	Volume (A)		Maturity
	(In millions)
Short Financial Swaps/Futures (fixed)	NGLs		0.4	Current

Long Financial Swaps/Futures (fixed)	NGLs		0.4	Current

Physical Purchases (B)	Natural Gas		16.6	Current
Physical Purchases (B)	Natural Gas		5.8	Non-Current
Total Physical Purchases			22.4

Physical Sales (B)	Natural Gas		30.1	Current
Physical Sales (B)	Natural Gas		16.8	Non-Current
Total Physical Sales			46.9

Long Financial Swaps/Futures (fixed)	Natural Gas		34.7	Current
Long Financial Swaps/Futures (fixed)	Natural Gas		1.5	Non-Current
Total Long Financial Swaps/Futures (fixed)			36.2

Short Financial Swaps/Futures (fixed)	Natural Gas		35.2	Current
Short Financial Swaps/Futures (fixed)	Natural Gas		3.0	Non-Current
Total Short Financial Swaps/Futures (fixed)			38.2

Purchased Financial Option	Natural Gas		20.1	Current

Sold Financial Option	Natural Gas		18.8	Current

Long Financial Basis Swaps	Natural Gas		11.1	Current
Long Financial Basis Swaps	Natural Gas		1.5	Non-Current
Total Long Financial Basis Swaps			12.6

Short Financial Basis Swaps	Natural Gas		9.8	Current
Short Financial Basis Swaps	Natural Gas		1.5	Non-Current
Total Short Financial Basis Swaps			11.3
(A) Natural gas in MMBtu; NGLs in barrels.
(B) Of the natural gas physical purchases and sales volumes not designated as cash flow or fair value hedges, the majority are priced based on a monthly or daily index and the fair value is subject to little or no market price risk.

Balance Sheet Presentation Related to Derivative Instruments

The fair value of the derivative instruments that are presented in the Company’s Condensed Consolidated Balance Sheet at June 30, 2010 are as follows:

					Fair Value
		Balance Sheet
Instrument	Commodity	Location			Assets			Liabilities
				(In millions)
Derivatives Designated as Hedging Instruments

Financial Options	NGLs	Current PRM	$			26.2	$		---
		Non-Current PRM				14.4			---
Financial Futures/Swaps	NGLs	Current PRM				0.1			0.7
Financial Futures/Swaps	Natural Gas	Current PRM				---			23.5
		Non-Current PRM				---			12.2
		Other Current Assets				3.1			0.1
Total Gross Derivatives Designated as Hedging Instruments			$			43.8	$		36.5

Derivatives Not Designated as Hedging Instruments

Financial Futures/Swaps (A)	NGLs	Current PRM	$			1.4	$		1.1
Financial Futures/Swaps (B)	Natural Gas	Current PRM				3.0			7.2
		Other Current Assets				11.5			14.0
Physical Purchases/Sales	Natural Gas	Current PRM				1.7			1.5
		Non-Current PRM				0.3			---
Financial Options	Natural Gas	Other Current Assets				1.1			1.0
Total Gross Derivatives Not Designated as Hedging Instruments			$			19.0	$		24.8
Total Gross Derivatives (C)			$			62.8	$		61.3

(A)	The fair value of Financial Futures/Swaps – NGLs not designated as hedging instruments includes derivatives that were previously designated as hedging instruments and subsequently de-designated and off-setting derivatives were entered to close the hedge positions. The referenced derivatives had a fair value as presented in the table above in Current Assets of approximately $1.4 million and Current Liabilities of approximately $1.1 million.
(B)	The fair value of Financial Futures/Swaps – Natural Gas not designated as hedging instruments includes derivatives that were previously designated as hedging instruments and subsequently de-designated and off-setting derivatives were entered to close the hedge positions. The referenced derivatives had a fair value as presented in the table above in Current Assets of approximately $2.1 million and Current Liabilities of approximately $6.8 million.
(C)	See reconciliation of the Company’s total derivatives fair value to the Company’s Condensed Consolidated Balance Sheet at June 30, 2010 (see Note 2).

The fair value of the derivative instruments that are presented in the Company’s Condensed Consolidated Balance Sheet at December 31, 2009 are as follows:

						Fair Value
			Balance Sheet
Instrument		Commodity	Location			Assets			Liabilities
					(In millions)
Derivatives Designated as Hedging Instruments

Financial Options		NGLs	Current PRM	$			16.4	$		---
			Non-Current PRM				23.4			---
Financial Futures/Swaps		NGLs	Current PRM				---			6.1
Financial Futures/Swaps		Natural Gas	Current PRM				---			14.8
			Non-Current PRM				---			19.7
			Other Current Assets				4.6			1.2
Total Gross Derivatives Designated as Hedging Instruments				$			44.4	$		41.8

Derivatives Not Designated as Hedging Instruments

Financial Futures/Swaps (D)		NGLs	Current PRM	$			9.2	$		8.6
Financial Futures/Swaps (E)		Natural Gas	Current PRM				3.6			12.3
			Non-Current PRM				---			0.1
			Other Current Assets				11.8			13.6
Physical Purchases/Sales		Natural Gas	Current PRM				0.8			0.6
			Non-Current PRM				0.6			---
Financial Options		Natural Gas	Other Current Assets				0.9			0.8
Total Gross Derivatives Not Designated as Hedging Instruments				$			26.9	$		36.0
Total Gross Derivatives (F)				$			71.3	$		77.8
(D)	The entire fair value of Financial Futures/Swaps – NGLs not designated as hedging instruments includes derivatives that were previously designated as hedging instruments and subsequently de-designated with offsetting derivatives to close the hedge positions.
(E)	The fair value of Financial Futures/Swaps – Natural Gas not designated as hedging instruments includes derivatives that were previously designated as hedging instruments and subsequently de-designated with offsetting derivatives to close the hedge positions. The referenced derivatives had a fair value as presented in the table above in Current Assets of approximately $2.9 million and Current Liabilities of approximately $11.7 million.
(F)	See reconciliation of the Company’s total derivatives fair value to the Company’s Condensed Consolidated Balance Sheet at December 31, 2009 (see Note 2).

Income Statement Presentation Related to Derivative Instruments

The following table presents the effect of derivative instruments on the Company’s Condensed Consolidated Statement of Income for the three months ended June 30, 2010.

Amount of

Gain or Loss

Amount of

Location of Gain or

Recognized

Gain or Loss

Loss Recognized in

in Income on

Amount of Gain

Reclassified

Income on

Derivative

or Loss

from

Derivative

(Ineffective

Recognized in

Location of Gain or

Accumulated

(Ineffective Portion

Portion and

OCI on

Loss Reclassified

OCI into

and Amount

Amount

Derivative

from Accumulated

Income

Excluded from

(Effective

OCI into Income

(Effective

Effectiveness

Instrument

Portion)(A)

(Effective Portion)

Portion)

Testing)

(In millions)
Derivatives in Cash Flow Hedging Relationships

NGLs Financial Options	$	10.5	Operating Revenues	$	1.1	Operating Revenues	$	---
NGLs Financial
Futures/Swaps		2.0	Operating Revenues		(0.5)	Operating Revenues		---
Natural Gas Financial
Futures/Swaps		---	Operating Revenues		(8.6)	Operating Revenues		---
Total	$	12.5	Total	$	(8.0)	Total	$	---

(A) The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at June 30, 2010 that is expected to be reclassified into

earnings within the next 12 months is a loss of approximately $12.5 million.

Amount of Gain or

Location of Gain or

Loss Recognized in

Income of

Income on Derivative

Derivative

(In millions)

Derivatives Not Designated as Hedging Instruments

Natural Gas Physical Purchases/Sales

Operating Revenues

(3.7)

Natural Gas Financial Futures/Swaps

Operating Revenues

(0.6)

Total

(4.3)

The following table presents the effect of derivative instruments on the Company’s Condensed Consolidated Statement of Income for the three months ended June 30, 2009.

Amount of

Gain or Loss

Amount of

Location of Gain or

Recognized

Gain or Loss

Loss Recognized in

in Income on

Amount of Gain

Reclassified

Income on

Derivative

or Loss

from

Derivative

(Ineffective

Recognized in

Location of Gain or

Accumulated

(Ineffective Portion

Portion and

OCI on

Loss Reclassified

OCI into

and Amount

Amount

Derivative

from Accumulated

Income

Excluded from

(Effective

OCI into Income

(Effective

Effectiveness

Instrument

Portion)

(Effective Portion)

Portion)

Testing)

(In millions)
Derivatives in Cash Flow Hedging Relationships

NGLs Financial Options	$	(23.9)	Operating Revenues	$	1.2	Operating Revenues	$	---
NGLs Financial
Futures/Swaps		(20.4)	Operating Revenues		4.6	Operating Revenues		---
Natural Gas Financial
Futures/Swaps		5.9	Operating Revenues		(12.3)	Operating Revenues		(0.3)
Total	$	(38.4)	Total	$	(6.5)	Total	$	(0.3)

Amount of Gain or

Location of Gain or

Loss Recognized in

Income of

Income on Derivative

Derivative

(In millions)

Derivatives Not Designated as Hedging Instruments

Natural Gas Physical Purchases/Sales

Operating Revenues

(2.3)

Natural Gas Financial Futures/Swaps

Operating Revenues

1.8

Total

(0.5)

The following table presents the effect of derivative instruments on the Company’s Condensed Consolidated Statement of Income for the six months ended June 30, 2010.

Amount of

Gain or Loss

Amount of

Location of Gain or

Recognized

Gain or Loss

Loss Recognized in

in Income on

Amount of Gain

Reclassified

Income on

Derivative

or Loss

from

Derivative

(Ineffective

Recognized in

Location of Gain or

Accumulated

(Ineffective Portion

Portion and

OCI on

Loss Reclassified

OCI into

and Amount

Amount

Derivative

from Accumulated

Income

Excluded from

(Effective

OCI into Income

(Effective

Effectiveness

Instrument

Portion)(A)

(Effective Portion)

Portion)

Testing)

(In millions)
Derivatives in Cash Flow Hedging Relationships

NGLs Financial Options	$	11.0	Operating Revenues	$	0.5	Operating Revenues	$	---
NGLs Financial
Futures/Swaps		3.3	Operating Revenues		(1.8)	Operating Revenues		---
Natural Gas Financial
Futures/Swaps		(9.9)	Operating Revenues		(12.0)	Operating Revenues		0.1
Total	$	4.4	Total	$	(13.3)	Total	$	0.1

(A) The estimated net amount of gains or losses included in Accumulated Other Comprehensive Income at June 30, 2010 that is expected to be reclassified into

earnings within the next 12 months is a loss of approximately $12.5 million.

Amount of Gain or

Location of Gain or

Loss Recognized in